form10qlpq1042711.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2011

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _________ to _________

Commission File Number: 000-26091

TC PipeLines, LP

(Exact name of registrant as specified in its charter)

Delaware	52-2135448
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

13710 FNB Parkway Omaha, Nebraska	68154-5200
(Address of principle executive offices)	(Zip code)

877-290-2772

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x	Accelerated filer ¨
Non-accelerated filer ¨ (Do not check if a smaller reporting company)	Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ¨ No x

As at April 27, 2011 there were 46,227,766 of the registrant’s common units outstanding.

TABLE OF CONTENTS

Page No.

GLOSSARY		3

PART I	FINANCIAL INFORMATION

Item 1.	Financial Statements	4

	Consolidated Statement of Income – Three months ended March 31, 2011 and 2010	4
	Consolidated Statement of Comprehensive Income – Three months ended March 31, 2011 and 2010	4
	Consolidated Balance Sheet – March 31, 2011 and December 31, 2010	5
	Consolidated Statement of Cash Flows – Three months ended March 31, 2011 and 2010	6
	Consolidated Statement of Changes in Partners’ Equity – Three months ended March 31, 2011	7
	Notes to Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	27

Item 4.	Controls and Procedures	29

PART II	OTHER INFORMATION

Item 1.	Legal Proceedings	30

Item 1A.	Risk Factors	30

Item 5	Other Information	31

Item 6.	Exhibits	32

All amounts are stated in United States dollars unless otherwise indicated.

GLOSSARY

The abbreviations, acronyms, and industry terminology used in this quarterly report are defined as follows:

Acquisition	The agreements to acquire from TAIL and TC Continental a 25 percent interest in GTN and a 25 percent interest in Bison, respectively
Bison	Bison Pipeline LLC
Complainants	NV Energy and the PUCN, collectively
Design capacity	Pipeline capacity available to transport natural gas based on system facilities and design conditions
FERC	Federal Energy Regulatory Commission
GAAP	U.S. generally accepted accounting principles
Gas exiting the WCSB	Net of the supply of and demand for natural gas in the WCSB region that is available for transportation to downstream markets; where supply represents WCSB production adjusted for injections into and withdrawals from WCSB storage
General Partner	TC PipeLines GP, Inc.
GL Rate Proceeding	FERC investigation into Great Lakes’ rates pursuant to Section 5 of the NGA
GL Settlement	Stipulation and agreement approved by the FERC on July 15, 2010 establishing the terms pursuant to which all matters in the GL Rate Proceeding were resolved
Great Lakes	Great Lakes Gas Transmission Limited Partnership
GTN	Gas Transmission Northwest LLC
LIBOR	London Interbank Offered Rate
MDth/d	Thousand dekatherms per day
MMcf/d	Million cubic feet per day
NGA	Natural Gas Act
North Baja	North Baja Pipeline, LLC
Northern Border	Northern Border Pipeline Company
NV Energy	Sierra Pacific Power Company d/b/a NV Energy
Other Pipes	North Baja and Tuscarora
Our pipeline systems	Great Lakes, Northern Border, North Baja and Tuscarora
Partnership	TC PipeLines, LP and its subsidiaries
Partnership Agreement	Second Amended and Restated Agreement of Limited Partnership
PUCN	Public Utilities Commission of Nevada
RREI	Rolls Royce Energy Systems, Inc.
SEC	Securities and Exchange Commission
Senior Credit Facility	TC PipeLines’ revolving credit and term loan agreement
TC Continental	TC Continental Pipeline Holdings Inc.
TransCanada	TransCanada Corporation and its subsidiaries
TAIL	TransCanada American Investments Ltd.
TCPL	TransCanada PipeLines Limited
Tuscarora	Tuscarora Gas Transmission Company
U.S.	United States of America
WCSB	Western Canada Sedimentary Basin
Yuma Lateral	An expansion of the North Baja pipeline from the Mexico/Arizona border to Yuma, Arizona

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF INCOME

(unaudited)	Three months ended March 31,
(millions of dollars except per common unit amounts)	2011			2010

Equity income from investment in Great Lakes (Note 2)		18.0			16.3
Equity income from investment in Northern Border (Note 3)		20.6			14.6
Transmission revenues		17.3			17.4
Operating expenses		(3.1	)		(3.4	)
General and administrative		(1.8	)		(1.3	)
Depreciation		(3.7	)		(3.7	)
Financial charges and other		(5.0	)		(6.2	)
Net income		42.3			33.7

Net income allocation (Note 6)
Common units		41.5			33.0
General partner		0.8			0.7
		42.3			33.7

Net income per common unit (Note 6)		$0.90			$0.71

Weighted average common units outstanding (millions)		46.2			46.2

Common units outstanding, end of the period (millions)		46.2			46.2

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(unaudited)	Three months ended March 31,
(millions of dollars)	2011		2010

Net income		42.3		33.7
Other comprehensive income
Change associated with hedging transactions (Note 10)		3.9		1.6
Total comprehensive income		46.2		35.3

The accompanying notes are an integral part of these consolidated financial statements.

TC PIPELINES, LP

CONSOLIDATED BALANCE SHEET

(unaudited)
(millions of dollars)	March 31, 2011			December 31, 2010
ASSETS
Current Assets
Cash and cash equivalents		2.9			3.6
Accounts receivable and other (Note 11)		8.6			8.7
		11.5			12.3
Investment in Great Lakes (Note 2)		695.4			690.0
Investment in Northern Border (Note 3)		499.6			504.8
Plant, property and equipment
(net of $137.0 accumulated depreciation; 2010 – $133.3)		308.8			312.6
Goodwill		130.2			130.2
Other assets		0.6			0.6
		1,646.1			1,650.5

LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities		6.3			7.7
Accrued interest		2.1			1.3
Current portion of long-term debt (Note 5)		475.8			483.8
Current portion of fair value of derivative contracts (Note 10)		9.9			13.8
		494.1			506.6
Long-term debt (Note 5)		30.1			30.1
Other liabilities		0.9			1.3
		525.1			538.0
Partners' Equity
Common units		1,108.7			1,104.2
General partner		23.6			23.5
Accumulated other comprehensive loss		(11.3	)		(15.2	)
		1,121.0			1,112.5
		1,646.1			1,650.5

Subsequent events (Note 12)

The accompanying notes are an integral part of these consolidated financial statements.

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CASH FLOWS

(unaudited)	Three months ended March 31,
(millions of dollars)	2011			2010

CASH GENERATED FROM OPERATIONS
Net income		42.3			33.7
Depreciation		3.7			3.7
Amortization of other assets		0.1			0.1
Equity income in excess of distributions received from Great Lakes		(1.1	)		(0.6	)
(Decrease)/increase in long-term liabilities		(0.3	)		0.1
Equity allowance for funds used during construction		-			(0.2	)
(Increase)/decrease in operating working capital (Note 8)		(0.4	)		0.6
		44.3			37.4

INVESTING ACTIVITIES
Cumulative distributions in excess of equity earnings:
Northern Border		5.2			1.7
Investment in Great Lakes (Note 2)		(4.3	)		(2.3	)
Capital expenditures (Note 4)		(2.4	)		(8.5	)
Increase in investing working capital (Note 8)		(0.1	)		-
		(1.6	)		(9.1	)

FINANCING ACTIVITIES
Distributions paid (Note 7)		(35.4	)		(34.4	)
Long-term debt issued (Note 5)		-			10.0
Long-term debt repaid (Note 5)		(8.0	)		(3.0	)
		(43.4	)		(27.4	)

(Decrease)/increase in cash and cash equivalents		(0.7	)		0.9
Cash and cash equivalents, beginning of period		3.6			3.1

Cash and cash equivalents, end of period		2.9			4.0

Interest payments made		0.8			1.2

The accompanying notes are an integral part of these consolidated financial statements.

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

(unaudited)	Common Units					General Partner			Accumulated Other Comprehensive (Loss)/Income(a)			Partners' Equity
	(millions		(millions			(millions			(millions			(millions		(millions
	of units)		of dollars)			of dollars)			of dollars)			of units)		of dollars)

Partners' equity at December 31, 2010		46.2		1,104.2			23.5			(15.2	)		46.2		1,112.5
Net income		-		41.5			0.8			-			-		42.3
Distributions paid		-		(34.7	)		(0.7	)		-			-		(35.4	)
Excess purchase price over net acquired assets (Note 4)		-		(2.3	)		-			-			-		(2.3	)
Other comprehensive income		-		-			-			3.9			-		3.9
Partners' equity at March 31, 2011		46.2		1,108.7			23.6			(11.3	)		46.2		1,121.0

(a) The Partnership uses derivatives to assist in managing its exposure to interest rate risk. Based on interest rates at March 31, 2011, the amount of losses related to cash flow hedges reported in accumulated other comprehensive income that will be reclassified to net income in the next 12 months is $9.9 million, which will be offset by a reduction to interest expense of a similar amount.

The accompanying notes are an integral part of these consolidated financial statements.

TC PIPELINES, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 ORGANIZATION

TC PipeLines, LP and its subsidiaries are collectively referred to herein as “the Partnership.” In this report, references to “we,” “us” or “our” refer to the Partnership.

The preparation of financial statements in conformity with United States of America (U.S.) generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates. In the opinion of management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and include all adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the financial results for the interim periods presented.

The results of operations for the three months ended March 31, 2011 and 2010 are not necessarily indicative of the results that may be expected for a full fiscal year. The unaudited interim financial statements should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2010. Our significant accounting policies are consistent with those disclosed in Note 2 of the financial statements in our Annual Report on Form 10-K for the year ended December 31, 2010.

NOTE 2 INVESTMENT IN GREAT LAKES

We own a 46.45 percent general partner interest in Great Lakes Gas Transmission Limited Partnership (Great Lakes). Great Lakes is regulated by the Federal Energy Regulatory Commission (FERC) and is operated by a wholly-owned subsidiary of TransCanada Corporation (which, together with its subsidiaries, is referred to as TransCanada.)

We use the equity method of accounting for our interest in Great Lakes. Great Lakes had no undistributed earnings for the three months ended March 31, 2011 and 2010.

The Partnership made an equity contribution to Great Lakes of $4.2 million in the first quarter of 2011. This amount represents the Partnership’s 46.45 percent share of a $9.0 million cash call from Great Lakes to make a scheduled debt repayment.

The following tables contain summarized financial information of Great Lakes:

Summarized Great Lakes Balance Sheet

(unaudited)	March 31,		December 31,
(millions of dollars)	2011		2010
Assets
Other current assets		90.6		83.7
Plant, property and equipment, net		839.9		846.9
Other assets		0.7		0.6
		931.2		931.2
Liabilities and Partners' Equity
Current liabilities		32.1		34.9
Deferred credits		6.1		5.6
Long-term debt, net of current maturities		383.0		392.0
Partners' capital		510.0		498.7
		931.2		931.2

Summarized Great Lakes Income Statement

(unaudited)	Three months ended March 31,
(millions of dollars)	2011			2010
Transmission revenues		70.2			72.9
Operating expenses		(14.3	)		(14.2	)
Depreciation		(8.1	)		(14.3	)
Financial charges and other		(7.6	)		(7.9	)
Michigan business tax		(1.6	)		(1.5	)
Net income		38.6			35.0

NOTE 3 INVESTMENT IN NORTHERN BORDER

We own a 50 percent general partner interest in Northern Border Pipeline Company (Northern Border). Northern Border is regulated by the FERC and is operated by a wholly-owned subsidiary of TransCanada.

We use the equity method of accounting for our interest in Northern Border. Northern Border had no undistributed earnings for the three months ended March 31, 2011 and 2010.

The following tables contain summarized financial information of Northern Border:

Summarized Northern Border Balance Sheet

(unaudited)	March 31,			December 31,
(millions of dollars)	2011			2010
Assets
Cash and cash equivalents		12.4			10.2
Other current assets		34.8			37.1
Plant, property and equipment, net		1,282.9			1,294.8
Other assets		23.6			22.9
		1,353.7			1,365.0
Liabilities and Partners' Equity
Current liabilities		44.6			46.7
Deferred credits and other		10.2			9.7
Long-term debt, net of current maturities		540.6			540.6
Partners' equity
Partners' capital		761.1			770.9
Accumulated other comprehensive loss		(2.8	)		(2.9	)
		1,353.7			1,365.0

Summarized Northern Border Income Statement

(unaudited)	Three months ended March 31,
(millions of dollars)	2011			2010
Transmission revenues		80.2			69.1
Operating expenses		(17.5	)		(18.0	)
Depreciation		(15.3	)		(15.4	)
Financial charges and other		(5.7	)		(6.0	)
Net income		41.7			29.7

NOTE 4 ASSET ACQUISITION

Yuma Lateral Asset Acquisition

The June 29, 2010 First Amendment to the North Baja Acquisition Agreement provided that the Partnership make an additional payment of up to $2.4 million to TransCanada in the event that certain other shippers contracted for services on the Yuma Lateral before December 31, 2010. On July 28, 2010, TransCanada secured an additional contract and, as a result, on March 25, 2011, an additional payment of $2.4 million was paid to TransCanada when the facilities associated with the additional contract were completed.

NOTE 5 CREDIT FACILITIES AND LONG-TERM DEBT

(unaudited)	March 31,		December 31,
(millions of dollars)	2011		2010

Senior Credit Facility due 2011		475.0		483.0
6.89% Series C Senior Notes due 2012		3.9		3.9
3.82% Series D Senior Notes due 2017		27.0		27.0
		505.9		513.9
Less: current portion of long-term debt		475.8		483.8
		30.1		30.1

The Partnership’s Senior Credit Facility consists of a $475.0 million senior term loan and a $250.0 million senior revolving credit facility, maturing December 2011. At March 31, 2011, there were no amounts drawn under the senior revolving credit facility (December 31, 2010 – $8.0 million) and $475.0 million remained outstanding under the senior term loan (December 31, 2010 – $475.0 million). The interest rate on the Senior Credit Facility averaged 0.83 percent for the three months ended March 31, 2011 (2010 – 0.9 percent). After hedging activity, the interest rate incurred on the Senior Credit Facility averaged 4.01 percent for the three months ended March 31, 2011 (2010 – 4.3 percent). Prior to hedging activities, the interest rate was 0.79 percent at March 31, 2011 (December 31, 2010 – 0.83 percent). At March 31, 2011, the Partnership was in compliance with its financial covenants, in addition to the other covenants, which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Partnership Agreement, incurring additional debt and distributions to unitholders. The Partnership expects to renew its Senior Credit Facility prior to its maturity date of December 12, 2011.

The principal repayments required on our long-term debt are as follows:

(unaudited)
(millions of dollars)
2011	475.8
2012	3.1
2013	3.5
2014	3.6
2015	3.7
Thereafter	16.2
	505.9

NOTE 6 NET INCOME PER COMMON UNIT

Net income per common unit is computed by dividing net income, after deduction of TC PipeLines GP, Inc.’s (General Partner) allocation, by the weighted average number of common units outstanding. The General Partner’s allocation is equal to an amount based upon the General Partner’s two percent interest, plus an amount equal to incentive distributions. Incentive distributions are paid to the General Partner if quarterly cash distributions on the common units exceed levels specified in the Partnership Agreement.

Net income per common unit was determined as follows:

(unaudited)	Three months ended March 31,
(millions of dollars except per common unit amounts)	2011			2010
Net income		42.3			33.7
Net income allocated to General Partner		(0.8	)		(0.7	)
Net income allocable to common units		41.5			33.0
Weighted average common units outstanding (millions)		46.2			46.2
Net income per common unit		$0.90			$0.71

NOTE 7 CASH DISTRIBUTIONS

For the three months ended March 31, 2011, the Partnership distributed $0.75 per common unit (2010 – $0.73 per common unit). The distributions paid for the three months ended March 31, 2011 included no incentive distributions to the General Partner (2010 – $nil).

NOTE 8 CHANGE IN WORKING CAPITAL

(unaudited)	Three months ended March 31,
(millions of dollars)	2011			2010

Decrease in accounts receivable and other		0.1			0.6
Decrease in accounts payable and accrued liabilities		(1.4	)		(1.2	)
Increase in accrued interest		0.8			1.2
		(0.5	)		0.6
Increase in investing working capital		(0.1	)		-
(Increase)/decrease in operating working capital		(0.4	)		0.6

NOTE 9 RELATED PARTY TRANSACTIONS

The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership. The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. Total costs charged to the Partnership by the General Partner were $0.6 million for the three months ended March 31, 2011 (2010 – $0.5 million).

As operator, TransCanada’s subsidiaries provide capital and operating services to Great Lakes, Northern Border, North Baja and Tuscarora (together, “our pipeline systems”). TransCanada’s subsidiaries incur costs on behalf of our pipeline systems, including, but not limited to, employee salary and benefit costs, and property and liability insurance costs.

Costs charged to our pipeline systems for the three months ended March 31, 2011 and 2010 by TransCanada’s subsidiaries, and amounts payable to TransCanada’s subsidiaries at March 31, 2011 and December 31, 2010, are summarized in the following tables:

(unaudited)	Three months ended March 31,
(millions of dollars)	2011		2010
Costs charged by TransCanada's subsidiaries:
Great Lakes		7.8		7.6
Northern Border		6.7		6.9
North Baja		0.8		0.8
Tuscarora		0.9		0.9
Impact on the Partnership's net income:
Great Lakes		3.5		3.4
Northern Border		3.2		3.2
North Baja		0.7		0.7
Tuscarora		0.9		0.9

(unaudited)	March 31,		December 31,
(millions of dollars)	2011		2010

Amount payable to TransCanada's subsidiaries for costs charged in the period:
Great Lakes		2.9		3.0
Northern Border		2.2		2.2
North Baja		0.8		0.6
Tuscarora		0.8		0.7

Great Lakes earns transportation revenues from TransCanada and its affiliates under contracts with fixed prices. The contracts have remaining terms ranging from one to seven years. Great Lakes earned $24.4 million of transportation revenues under these contracts for the three months ended March 31, 2011 (2010 – $40.0 million). This amount represents 34.8 percent of total revenues earned by Great Lakes for the three months ended March 31, 2011 (2010 – 54.9 percent). Great Lakes also earned $0.3 million in affiliated rental revenue for the three months ended March 31, 2011 (2010 – $0.1 million).

Revenue from TransCanada and its affiliates of $11.5 million is included in the Partnership’s equity income from Great Lakes for the three months ended March 31, 2011 (2010 – $18.6 million). At March 31, 2011, $9.3 million was included in Great Lakes’ receivables for transportation contracts with TransCanada and its affiliates (December 31, 2010 – $11.0 million).

NOTE 10 FINANCIAL INSTRUMENTS

The carrying value of cash and cash equivalents, accounts receivable and other, accounts payable and accrued liabilities, and accrued interest approximate their fair values because of the short maturity or duration of these instruments, or because the instruments carry a variable rate of interest or a rate that approximates current rates. The fair value of the Partnership’s long-term debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The estimated fair value of the Partnership’s long-term debt at March 31, 2011 is $505.7 million (December 31, 2010 – $513.9 million).

The Partnership’s long-term debt results in exposures to changing interest rates. The Partnership uses derivatives to assist in managing its exposure to interest rate risk.

The interest rate swaps and options are structured such that the cash flows match those of the Senior Credit Facility. The notional amount hedged was $300.0 million at March 31, 2011 (December 31, 2010 – $375.0 million). $300.0 million of variable-rate debt is hedged by an interest rate swap through December 12, 2011, where the weighted average fixed interest rate paid is 4.89 percent. $75.0 million of variable-rate debt was hedged by an interest rate swap through February 28, 2011, where the fixed interest rate paid was 3.86 percent. In addition to these fixed rates, the Partnership pays an applicable margin in accordance with the Senior Credit Facility agreement.

Financial instruments are recorded at fair value on a recurring basis and are categorized into one of three categories based upon a fair value hierarchy. The Partnership has classified all of its derivative financial instruments as Level II for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. At March 31, 2011, the fair value of the interest rate swaps accounted for as hedges was classified as a current liability and was negative $9.9 million (December 31, 2010 – negative $13.8 million). The fair value of the interest rate swaps was calculated using the period-end interest rate; therefore, it is expected that this fair value will fluctuate over the year as interest rates change. For the three months ended March 31, 2011, the Partnership recorded interest expense of $3.9 million on the interest rate swaps and options (2010 – $4.2 million).

NOTE 11 ACCOUNTS RECEIVABLE AND OTHER

(unaudited)	March 31,		December 31,
(millions of dollars)	2011		2010
Accounts receivable		7.6		7.6
Inventory		0.8		0.7
Prepayments		0.2		0.4
		8.6		8.7

NOTE 12 SUBSEQUENT EVENTS

On April 18, 2011, the board of directors of our General Partner declared the Partnership’s first quarter 2011 cash distribution in the amount of $0.75 per common unit, payable on May 13, 2011 to unitholders of record as of April 30, 2011.

Great Lakes declared and will pay its first quarter distribution of $46.2 million on May 2, 2011, of which the Partnership will receive its 46.45 percent share or $21.4 million.

Northern Border declared and will pay its first quarter distribution of $53.1 million on May 2, 2011, of which the Partnership will receive its 50 percent share or $26.5 million.

On April 26, 2011, the Partnership and TransCanada American Investments Ltd. (TAIL), a subsidiary of TransCanada, entered into a Purchase and Sale Agreement whereby the Partnership will acquire from TAIL a 25 percent interest in Gas Transmission Northwest LLC (GTN) for $405.0 million, which reflects 25 percent, or $81.3 million, of GTN's outstanding debt. On the same date, the Partnership and TC Continental Pipeline Holdings Inc. (TC Continental), a subsidiary of TransCanada, entered into a Purchase and Sale Agreement whereby the Partnership will acquire from TC Continental a 25 percent interest in Bison Pipeline LLC (Bison) for $200.0 million. The acquisition of a 25 percent interest in each of GTN and Bison is referred to herein as the "Acquisition."

The Partnership also has a commitment with SunTrust Robinson Humphrey, Inc., as Arranger, for up to $400.0 million in bridge financing, which together with availability under the Partnership’s senior revolving credit facility, will be available to fund the aggregate purchase price at closing of approximately $520.0 million for the Acquisition. Longer term financing for the Acquisition is expected to include a combination of debt and equity. The Acquisition, subject to certain closing conditions, and the bridge transaction is expected to close in May.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discusses the results of operations and liquidity and capital resources of TC PipeLines, LP (the Partnership), along with those of our pipeline systems. We use “our pipeline systems” when referring to the Partnership’s ownership interests in Great Lakes Gas Transmission Limited Partnership (Great Lakes), Northern Border Pipeline Company (Northern Border), North Baja Pipeline, LLC (North Baja) and Tuscarora Gas Transmission Company (Tuscarora).

FORWARD-LOOKING STATEMENTS

The statements in this report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). Forward-looking statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “forecast” and other words and terms of similar meaning. The absence of these words, however, does not mean that the statements are not forward-looking.

These statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions. Certain factors that could cause actual results to differ materially from those contemplated in the forward-looking statements include:

●	the ability of Great Lakes and Northern Border to continue to make distributions and North Baja and Tuscarora to continue to generate positive operating cash flows at their current levels;
●	the impact of unsold capacity on Great Lakes and Northern Border being greater or less than expected;
●	the competitive conditions in our industry and the ability of our pipeline systems to market pipeline capacity on favorable terms, which is affected by, among other factors: ○ future demand for and prices of natural gas; ○ level of natural gas basis differentials; ○ competitive conditions in the overall natural gas and electricity markets; ○ availability and relative cost of supplies of Canadian and United States (U.S.) natural gas, including the shale gas resources such as the Horn River and Montney deposits in Western Canada and the Bakken formation in the Midwestern U.S., along with U.S. Rockies, Mid-Continent and Marcellus natural gas developments; ○ competitive developments by U.S. and Canadian natural gas transmission companies; ○ the availability of additional storage capacity and current storage levels; ○ the level of liquefied natural gas imports; ○ weather conditions that impact supply and demand; and ○ the ability of shippers to meet creditworthiness requirements;
●	the impact of current and future laws, rulings and governmental regulations, particularly Federal Energy Regulatory Commission (FERC) regulations and rate proceedings including the FERC’s actions, if any, on the Tuscarora complaint, and proposed and pending legislation by Congress and proposed and pending regulations by the U.S. Environmental Protection Agency and other regulators in the U.S. on us and our pipeline systems;
●	the changes in relative cost structures of natural gas producing basins, such as changes in royalty programs, that may prejudice the development of the Western Canada Sedimentary Basin (WCSB);
●	decisions by other pipeline companies to advance projects that will affect our pipeline systems;
●	the regulatory, financing and construction risks related to construction of interstate natural gas pipelines and additional facilities;
●	our ability and that of our pipeline systems to identify and/or consummate expansion projects and other accretive growth opportunities;
●	the completion of our proposed acquisition of a 25 percent interest in Gas Transmission Northwest LLC (GTN) and a 25 percent interest in Bison Pipeline LLC (Bison);
●	entry into a bridge loan commitment with SunTrust Robinson Humphrey, Inc., as Arranger, and longer term financing for our planned acquisition of interests in GTN and Bison;

●	the performance of contractual obligations by customers of our pipeline systems;
●	the imposition of entity level taxation by states on partnerships;
●	the operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
●	our ability to control operating costs, including the operations of our pipeline systems; and
●	the general economic conditions in North America, which impact: ○ the debt and equity capital markets and our ability to access these markets at reasonable costs, including the refinancing of our Senior Credit Facility; ○ the overall demand for natural gas by end users; and ○ natural gas prices.

Other factors described elsewhere in this document, or factors that are unknown or unpredictable, could also have material adverse effects on future results. Please also read Item 1A. “Risk Factors.” All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. These forward-looking statements and information are made only as of the date of the filing of this report and except as required by applicable law, we undertake no obligation to update these forward-looking statements and information to reflect new information, subsequent events or otherwise.

The following discussion and analysis should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2010 and the unaudited financial statements and notes included in Item 1. “Financial Statements” of this Quarterly Report on Form 10-Q. All amounts are stated in U.S. dollars.

PARTNERSHIP OVERVIEW

TC PipeLines, LP was formed in 1998 as a Delaware limited partnership to acquire, own and participate in the management of energy infrastructure businesses in North America.

To date, our investments have been in interstate natural gas pipeline systems that transport natural gas to a variety of markets in the U.S. and Eastern Canada. Our pipeline systems derive their operating revenue from the transportation of natural gas. Our pipelines are regulated by the FERC and are operated by TransCanada Corporation’s subsidiaries (TransCanada Corporation, together with its subsidiaries, is referred to herein as TransCanada.) With the exception of North Baja, these pipelines comprise critical links for the transportation of natural gas from the WCSB to U.S. markets.

Our investments are:

	Ownership		System Specifications
	Percentage	Date Acquired	Length (Miles)	Capacity (MMcf/d)
Great Lakes	46.45	February 2007	2,115	2,300 (summer design) 2,500 (winter design)
Northern Border	30.00 20.00 50.00	May 1999 April 2006	1,398	2,374 (design)
North Baja	100.00	July 2009	86	500 (southbound design) 600 (northbound design)
Tuscarora	49.00 49.00 2.00 100.00	September 2000 December 2006 December 2007	305	230 (design)

RECENT DEVELOPMENTS

Partnership

GTN and Bison Acquisition

On April 26, 2011, the Partnership and TransCanada American Investments Ltd. (TAIL), a subsidiary of TransCanada, entered into a Purchase and Sale Agreement whereby the Partnership will acquire from TAIL a 25 percent interest in Gas Transmission Northwest LLC (GTN) for $405.0 million in cash less $81.3 million, which reflects 25 percent of GTN's outstanding debt. On the same date, the Partnership and TC Continental Pipeline Holdings Inc. (TC Continental), a subsidiary of TransCanada, entered into a Purchase and Sale Agreement whereby the Partnership will acquire from TC Continental a 25 percent interest in Bison Pipeline LLC (Bison) for $200.0 million in cash less a $9.0 million future capital commitment to complete the Bison pipeline. The acquisition of a 25 percent interest in each of GTN and Bison is referred to herein as the “Acquisition.”

The Conflicts Committee of the board of directors of TC PipeLines GP, Inc. (General Partner), composed entirely of independent directors, unanimously recommended approval of the Acquisition to the board of directors. The Conflicts Committee retained legal and financial advisors to assist it in evaluating and negotiating the Acquisition. The board of directors of the General Partner unanimously approved the terms of the Acquisition.

The Purchase and Sale Agreements contain customary representations and warranties and covenants by each of the parties. Completion of the Acquisition is conditioned upon, among other things: (i) the absence of certain legal impediments prohibiting the transactions, (ii) applicable regulatory approvals and (iii) the conditions precedent contained in the Purchase and Sale Agreements having been satisfied. In addition, the Acquisition is subject to certain closing adjustments.

Yuma Lateral Expansion Acquisition

Our Pipeline Systems

Tuscarora Complaint

On February 28, 2011, the Public Utilities Commission of Nevada (PUCN) and Sierra Pacific Power Company d/b/a NV Energy (NV Energy) (collectively, “Complainants”) filed a complaint with the FERC, pursuant to Section 5 of the National Gas Act (NGA), alleging that Tuscarora’s rates for jurisdictional services may be unjust and unreasonable and asking the FERC to investigate Tuscarora’s rates and to establish an interim rate reduction. Tuscarora filed its Answer to the complaint and are currently awaiting the FERC’s action, which is not subject to any deadline.

Refer to “Regulatory Environment – FERC Rate Proceedings – Tuscarora Complaint” for additional information.

FACTORS THAT IMPACT OUR BUSINESS

Factors that may impact demand for transportation service on any one pipeline system include the availability of natural gas supply at the pipeline system’s receipt points, the ability and willingness of natural gas shippers to utilize that system over alternative pipelines, transportation rates compared to other systems and the volume of natural gas delivered to the same market from other supply sources and storage facilities.

Prevailing market conditions and dynamic competitive factors in North America (particularly reduced natural gas exiting the WCSB, increased supply from other supply basin market areas served by our pipelines and the economic environment affecting the demand for natural gas) will continue to impact the value of transportation on our pipeline systems and their ability to market available capacity. Our pipeline systems actively market their available capacity and work closely with customers, including natural gas producers and end users, to ensure our pipelines are offering attractive services and competitive rates.

Supply

The primary source of natural gas transported by our pipeline systems, excluding North Baja, is the WCSB. Gas exiting the WCSB is dependent upon WCSB natural gas production levels, demand for natural gas in Western Canada, and the volume of natural gas injected into natural gas storage in Western Canada. The volume of gas exiting the WCSB was slightly higher in the first quarter of 2011 compared to the first quarter of 2010. No material change in WCSB production is expected in 2011.

Production from natural gas basins other than the WCSB represents supply competition for WCSB natural gas. U.S. natural gas production for the first quarter of 2011 was stronger compared to the same quarter in 2010. However, growth in natural gas production is expected to moderate in 2011 because of falling gas-directed drilling rig count in response to lower prices. Production from U.S. shale gas developments and sustained high levels of natural gas in storage continue to hold commodity prices at relatively low levels.

Demand

Demand for natural gas in North America is impacted by a variety of factors including weather conditions, economic conditions, government regulations and the availability and price of alternative energy sources. The demand for natural gas in the first quarter of 2011 remained consistent with demand in the first quarter of 2010. The commodity price of natural gas trended lower in the first quarter of 2011 compared to the average price in the first quarter of 2010, and continues to be tempered by the ongoing impacts of increased production from U.S. shale gas developments, moderate demand for natural gas in North America related to the economic environment and high levels of natural gas in storage. We expect that demand for natural gas will improve modestly along with the economic recovery, and that most of the growth in demand will result from increased demand for natural gas-fired electric generation.

Competition

Due to excess pipeline capacity, there is currently increased competition among natural gas pipelines for the transportation of gas exiting the WCSB. Factors impacting the competition for gas exiting the WCSB include levels of firm transportation contracts on each pipeline, demand for natural gas in the regions served by each pipeline and relative transportation values on each pipeline.

Transportation values on Northern Border have improved compared to the first quarter of 2010, and Northern Border is substantially contracted through the first quarter of 2012. Great Lakes is substantially contracted through October 2011. As a result, we expect that Northern Border and Great Lakes will have limited revenue and cash flow exposure to competitive factors through the first quarter of 2012 and the third quarter of 2011, respectively.

Contracting

The majority of our pipeline systems’ natural gas transportation services are provided through firm service transportation contracts with a reservation charge to reserve pipeline capacity, regardless of use, for the term of the contract. The revenues associated with capacity under firm service transportation contracts are not subject to fluctuations caused by changing supply and demand conditions, competition and customers. Customers with interruptible service transportation agreements may utilize available capacity on a pipeline system after firm service transportation requests are satisfied. Interruptible service customers are assessed commodity charges (or utilization fees) based on distance and the volume of natural gas they transport.

The following table provides information with respect to the revenue composition for our pipeline systems for the three months ended March 31, 2011:

	Three Months ended March 31, 2011 Revenue Composition
	Firm Contracts
	Capacity Reservation Charges	Variable Usage Fees	Interruptible Contracts & Other Services

Great Lakes	89%	4%	7%

Northern Border	90%	7%	3%

North Baja	97%	1%	2%

Tuscarora	100%	0%	0%

New major long-haul pipeline projects are typically underpinned by contracts for an original term equal to or greater than ten years. When this original term expires, shippers typically renew on an annual basis. Terms for interruptible transportation services range from day-to-day to multiple years. With the interconnection of the Bison pipeline to Northern Border, terms for transportation services for related capacity on Northern Border have contract terms of ten years. However, contract renewals for Great Lakes and the remaining Northern Border contracts are generally on an annual basis. Tuscarora has long-term contracts for the majority of its capacity with term expiries after 2016. Similarly, North Baja has long-term contracts for a substantial portion of its capacity with terms that mature between 2022 and 2031.

Average Daily Scheduled Volumes

The table below provides historical information on the average daily scheduled volumes for Great Lakes and Northern Border for the three months ended March 31, 2011 and 2010:

	Average Daily Scheduled Volumes (a)
	Three months ended March 31,
(million cubic feet per day)		2011	2010

Great Lakes		2,892	2,133
Northern Border		2,778	2,209

(a) Average daily scheduled volumes represent volumes of natural gas, irrespective of path or distance transported, from which variable usage fee revenue is earned. Average daily scheduled volumes are not presented for North Baja and Tuscarora as Partnership Cash Flows and Net Income from these investments are underpinned by long-term firm contracts and do not vary significantly with changes in utilization.

Great Lakes

Average daily scheduled volumes on Great Lakes’ pipeline system for the first quarter of 2011 increased to 2,892 million cubic feet per day (MMcf/d) compared to 2,133 MMcf/d for the first quarter of 2010 primarily as a result of increased firm contract utilization, higher demand for interruptible transportation service and increased backhaul volumes. Volume variances related to utilization of long-term firm contracts have a minimal impact on revenue earned from these contracts.

Great Lakes’ long-haul capacity contracts are generally subject to annual renewals. Contracting occurs throughout the year; however, shippers typically contract on Great Lakes for the upcoming natural gas year starting on November 1 of each year. As a result, Great Lakes is currently fully contracted through October 2011. Great Lakes’ largest shipper, TransCanada PipeLines Limited (TCPL), has 576 thousand dekatherms per day (MDth/d) of long-haul capacity under contract expiring on October 31, 2011. Negotiations related to these contracts have resulted in 314 MDth/d being recontracted by TCPL for one year through October 31, 2012.

Northern Border

Average daily scheduled volumes on Northern Border’s pipeline system for the first quarter of 2011 increased to 2,778 MMcf/d compared to 2,209 MMcf/d for the first quarter of 2010. Demand for transportation on Northern Border improved during the first quarter of 2011 primarily due to the completion of other pipeline projects that moved Mid-Continent natural gas supply to eastern markets and the relative economic value of Northern Border services compared with other transportation paths.

Northern Border’s capacity is generally subject to annual contract renewals, which occur throughout the year. Substantially all of Northern Border’s capacity has been sold through March 2012.

Outlook

Due to the relatively short-term contract profiles for Great Lakes and Northern Border, these systems may experience operating revenue volatility. We believe Great Lakes and Northern Border to be fundamental and competitive components of the natural gas pipeline infrastructure exiting the WCSB. Northern Border is substantially contracted through the first quarter of 2012, and Great Lakes is substantially contracted through October 2011. The level of contracting and, accordingly, revenues post-October 2011 for Great Lakes and post-March 2012 for Northern Border will depend on supply, demand and competition described above.

North Baja and Tuscarora are expected to provide stable revenues, subject to any FERC decisions on rates, as the capacity on both pipelines is contracted for the long term.

REGULATORY ENVIRONMENT

FERC Rate Proceedings

Tuscarora Complaint

Tuscarora operates pursuant to maximum transportation rates approved by the FERC in a July 2006 rate case settlement. A moratorium on the filing of future rate cases under NGA Sections 4 or 5 expired on May 31, 2010. On February 28, 2011, the PUCN and NV Energy filed a complaint with the FERC, pursuant to Section 5 of the NGA, alleging that Tuscarora’s rates for jurisdictional services may be unjust and unreasonable and asking the FERC to investigate Tuscarora’s rates and to establish an interim rate reduction. Tuscarora filed its Answer to the complaint on March 18, 2011. We are currently awaiting the FERC’s action on the Complaint and Answers, which is not subject to any deadline. We cannot predict at this time whether the FERC will initiate an investigation into Tuscarora’s rates or, if so, the outcome of such an investigation. If the FERC were to initiate an investigation into Tuscarora’s rates and find them unjust and unreasonable, the outcome could adversely affect our results of operations and cash flows.

HOW WE EVALUATE OUR OPERATIONS

We evaluate our business primarily on the basis of the underlying operating results for each of our pipeline systems, along with a measure of Partnership cash flows. This measure does not have any standardized meaning prescribed by U.S. generally accepted accounting principles (GAAP). It is, therefore, considered to be a non-GAAP measure and is unlikely to be comparable to similar measures presented by other entities. Partnership cash flows include cash distributions from the Partnership’s equity investments, Great Lakes and Northern Border, plus operating cash flows from the Partnership’s wholly-owned subsidiaries, North Baja and Tuscarora, net of Partnership costs and distributions declared to the General Partner.

RESULTS OF OPERATIONS OF TC PIPELINES, LP

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions, which cannot be known with certainty, that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ. There were no significant changes to the Partnership’s critical accounting policies and estimates during the three months ended March 31, 2011.

Information about our critical accounting policies and estimates is included under Item 7. “Management Discussion and Analysis of Financial Condition and Results of Operations,” in our Annual Report on Form 10-K for the year ended December 31, 2010.

NET INCOME

To supplement our financial statements, we have presented a comparison of the earnings contribution components from each of our investments. We have presented net income in this format to enhance investors’ understanding of the way management analyzes our financial performance. We believe this summary provides a more meaningful comparison of our net income to the prior year, as we account for our partially-owned pipeline systems using the equity method. The presentation of this additional information is not meant to be considered in isolation or as a substitute for results prepared in accordance with GAAP.

The shaded areas in the tables below disclose the results from Great Lakes and Northern Border, representing 100 per cent of each entity's operations for the given period.


	For the three months ended March 31, 2011															For the three months ended March 31, 2010
(unaudited) (millions of dollars)	PipeLP			Other Pipes(a)			Corp(b)			GLGT			NBPC(c)			PipeLP			Other Pipes(a)			Corp(b)			GLGT			NBPC(c)
Transmission revenues		17.3			17.3			-			70.2			80.2			17.4			17.4			-			72.9			69.1
Operating expenses		(3.1	)		(3.1	)		-			(14.3	)		(17.5	)		(3.4	)		(3.4	)		-			(14.2	)		(18.0	)
General and administrative		(1.8	)		-			(1.8	)		-			-			(1.3	)		-			(1.3	)		-			-
Depreciation		(3.7	)		(3.7	)		-			(8.1	)		(15.3	)		(3.7	)		(3.7	)		-			(14.3	)		(15.4	)
Financial charges and other		(5.0	)		-			(5.0	)		(7.6	)		(5.7	)		(6.2	)		(1.0	)		(5.2	)		(7.9	)		(6.0	)
Michigan business tax		-			-			-			(1.6	)		-			-			-			-			(1.5	)		-
											38.6			41.7												35.0			29.7
Equity income		38.6			-			-			18.0			20.6			30.9			-			-			16.3			14.6
Net income		42.3			10.5			(6.8	)		18.0			20.6			33.7			9.3			(6.5	)		16.3			14.6

(a) “Other Pipes” represents the results of North Baja and Tuscarora.

(b) “Corp” includes the costs of the Partnership, but excludes the costs of its subsidiaries.

(c) The Partnership owns a 50 percent general partner interest in Northern Border. Equity income from Northern Border includes the 12-year amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the Partnership’s additional 20 percent acquisition in April 2006.

First Quarter 2011 Compared with First Quarter 2010

Net income increased $8.6 million to $42.3 million in the first quarter of 2011 compared to $33.7 million in the same period in 2010. This increase was primarily due to higher equity income from Northern Border and Great Lakes together with higher net income from Other Pipes.

Equity income from Northern Border was $20.6 million in the first quarter of 2011, an increase of $6.0 million compared to the same period in 2010. The increase in equity income was primarily due to increased transmission revenues. Northern Border’s transmission revenues increased $11.1 million primarily due to increased demand for transportation services in the first quarter of 2011.

Equity income from Great Lakes was $18.0 million in the first quarter of 2011, an increase of $1.7 million compared to the same period in 2010. The increase in equity income was primarily due to depreciation rate reductions arising from the Section 5 rate case settlement in May 2010 (GL Settlement), partially offset by decreased transmission revenues. Great Lakes’ transmission revenues for the three months ended March 31, 2011 decreased $2.7 million compared to the same period last year due to the impact of the GL Settlement rates on long-term revenues.

Net income from Other Pipes, which includes results from North Baja and Tuscarora, was $10.5 million in the first quarter of 2011, an increase of $1.2 million compared to the same period in 2010. This increase was primarily due to lower financial charges from Tuscarora as a result of lower average interest rates and lower average debt outstanding attributable to the refinancing of a portion of senior notes in December 2010.

PARTNERSHIP CASH FLOWS

The Partnership uses the non-GAAP financial measures “Partnership cash flows” and “Partnership cash flows before General Partner distributions” as they provide measures of cash generated during the period to evaluate our cash distribution capability. As well, management uses these measures as a basis for recommendations to our General Partner’s board of directors regarding the distribution to be declared each quarter. Partnership cash flow information is presented to enhance investors’ understanding of the way that management analyzes the Partnership’s financial performance.

The Partnership calculates Partnership cash flows as net income, plus operating cash flows from the Partnership’s wholly-owned subsidiaries, North Baja and Tuscarora, and cash distributions received in excess of equity income form the Partnership’s equity investments, Great Lakes and Northern Border, net of distributions declared to the General Partner. Partnership cash flows before General Partner distributions represent Partnership cash flows prior to distributions declared to the General Partner.

Partnership cash flows and Partnership cash flows before General Partner distributions are provided as a supplement to GAAP financial results and are not meant to be considered in isolation or as substitutes for financial results prepared in accordance with GAAP.

Non-GAAP Measures

Reconciliations of Net Income to Partnership Cash Flows

	Three months ended March 31,
(unaudited)
(millions of dollars except per common unit amounts)	2011			2010
Net income		42.3			33.7
Add:
Cash distributions from Great Lakes(a)		16.9			15.7
Cash distributions from Northern Border(a)		25.8			16.4
Cash flows provided by North Baja's operating activities		6.8			4.7
Cash flows provided by Tuscarora's operating activities		6.3			7.2
		55.8			44.0
Less:
Equity income from investment in Great Lakes		(18.0	)		(16.3	)
Equity income from investment in Northern Border		(20.6	)		(14.6	)
North Baja's net income		(5.6	)		(5.4	)
Tuscarora's net income		(4.9	)		(3.9	)
		(49.1	)		(40.2	)
Partnership cash flows before General Partner distributions		49.0			37.5
General Partner distributions(b)		(0.7	)		(0.7	)
Partnership cash flows		48.3			36.8
Cash distributions declared		(35.4	)		(34.4	)
Cash distributions declared per common unit(c)		$0.75			$0.73
Cash distributions paid		(35.4	)		(34.4	)
Cash distributions paid per common unit(c)		$0.75			$0.73

(a) In accordance with the cash distribution policies of the respective pipeline systems, cash distributions from Great Lakes and Northern Border are based on their respective prior quarter financial results.

(b) General Partner distributions represent the cash distributions declared to the General Partner with respect to its two percent interest plus an amount equal to incentive distributions.

(c) Cash distributions declared per common unit and cash distributions paid per common unit are computed by dividing cash distributions, after the deduction of the General Partner’s allocation, by the number of common units outstanding. The General Partner’s allocation is computed based upon the General Partner’s two percent interest plus an amount equal to incentive distributions.

First Quarter 2011 Compared with First Quarter 2010

Partnership cash flows increased $11.5 million to $48.3 million in the first quarter of 2011 compared to $36.8 million in the same period of 2010. This increase was primarily due to increases in cash distributions from Northern Border of $9.4 million and Great Lakes of $1.2 million.

The Partnership paid distributions of $35.4 million in the first quarter of 2011, an increase of $1.0 million compared to the same period in 2011, due to an increase in the quarterly distribution of $0.02 per common unit in the third quarter of 2010.

Other Cash Flows

On March 25, 2011, the Partnership made a payment of $2.4 million in connection with the Yuma Lateral for the additional contract secured by TransCanada when the facilities associated with the additional contract were completed.

On March 25, 2011, the Partnership made an equity contribution of $4.2 million to Great Lakes that was used to fund debt repayments.

LIQUIDITY AND CAPITAL RESOURCES OF TC PIPELINES, LP

Overview

Our principal sources of liquidity include distributions received from our investments in Great Lakes and Northern Border, operating cash flows from North Baja and Tuscarora and our bank credit facility. The Partnership funds its operating expenses, debt service and cash distributions primarily with operating cash flow. Long-term capital needs may be met through the issuance of long-term debt and/or equity.

Summary of the Partnership’s Contractual Obligations

Yuma Lateral – The June 29, 2010 First Amendment to the North Baja Acquisition Agreement provided that the Partnership make an additional payment of up to $2.4 million to TransCanada in the event that certain other shippers contracted for services on the Yuma Lateral before December 31, 2010. On July 28, 2010, TransCanada secured an additional contract and, as a result, on March 25, 2011, an additional payment of $2.4 million was paid to TransCanada when the facilities associated with the additional contract were completed.

The Partnership’s Debt and Credit Facility

The following table summarizes the Partnership’s debt and credit facility outstanding as at March 31, 2011:

(unaudited)	Payments Due by Period
(millions of dollars)	Total		Less Than 1 Year		Long-term Portion

Senior Credit Facility due 2011		475.0		475.0		-
6.89% Series C Senior Notes due 2012		3.9		0.8		3.1
3.82% Series D Senior Notes due 2017		27.0		-		27.0
		505.9		475.8		30.1

Tuscarora’s Series C and D Senior Notes are secured by Tuscarora’s transportation contracts, supporting agreements and substantially all of Tuscarora’s property. The note purchase agreements contain certain provisions that include, among other items, limitations on additional indebtedness and distributions to partners.

Interest Rate Swaps and Options

The Partnership’s long-term debt results in exposures to changing interest rates. The Partnership uses derivatives to assist in managing its exposure to interest rate risk.

The interest rate swaps and options are structured such that the cash flows match those of the Senior Credit Facility. The notional amount hedged was $300.0 million at March 31, 2011 (December 31, 2010 – $375.0 million). Financial instruments are recorded at fair value on a recurring basis and are categorized into one of three categories based upon a fair value hierarchy. The Partnership has classified all of its derivative financial instruments as Level II for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. At March 31, 2011, the fair value of the interest rate swaps accounted for as hedges was classified as a current liability and was negative $9.9 million (December 31, 2010 – negative $13.8 million). The fair value of the interest rate swaps was calculated using the period-end interest rate; therefore, it is expected that this fair value will fluctuate over the year as interest rates change. In the three months ended March 31, 2011, the Partnership recorded interest expense of $3.9 million on the interest rate swaps and options (2010 – $4.2 million).

Capital Requirements

2011

The Partnership made an equity contribution of $4.2 million to Great Lakes in the first quarter of 2011. This amount represents the Partnership’s 46.45 percent share of a $9.0 million cash call issued by Great Lakes to make a scheduled debt repayment. The Partnership expects to make an equity contribution of $4.6 million to Great Lakes in the fourth quarter of 2011. This represents the Partnership’s 46.45 percent share of an expected $10.0 million cash call from Great Lakes to make a scheduled debt repayment.

Northern Border’s distribution policy adopted in 2006 defines minimum equity to total capitalization to be used by its Management Committee to establish the timing and amount of required equity contributions. In accordance with this policy, the Partnership expects to make a required equity contribution of $54.5 million in third quarter 2011 and an equity contribution of approximately $4.7 million to fund capital expenditures related to the Princeton Lateral Project.

The Partnership has entered into Purchase and Sale Agreements to acquire a 25 percent interest in each of GTN and Bison. The Partnership will fund the aggregate purchase price at closing of approximately $520.0 million by entering into a bridge loan commitment with SunTrust Robinson Humphrey, Inc., as Arranger, for up to $400.0 million and using the availability under the Partnership's senior revolving credit facility to fund the remaining amount. The Acquisition is subject to certain closing conditions and both the Acquisition, and the bridge transaction are expected to close in May.

To the extent the Partnership has any additional capital requirements with respect to our pipeline systems or acquisitions in the future, we expect to fund these requirements with operating cash flows, debt and/or equity.

2011 First Quarter Cash Distribution

On April 18, 2011, the Partnership announced that the board of directors of the General Partner declared the Partnership’s first quarter 2011 cash distribution in the amount of $0.75 per common unit. The first quarter cash distribution, totaling $35.4 million, will be paid on May 13, 2011 to unitholders of record as of the close of business on April 30, 2011 in the following manner: $34.7 million to common unitholders (including $4.3 million to the General Partner as holder of 5,797,106 common units and $8.5 million to TransCanada as holder of 11,287,725 common units) and $0.7 million to the General Partner in respect of its two percent general partner interest.

LIQUIDITY AND CAPITAL RESOURCES OF OUR PIPELINE SYSTEMS

Overview

Our pipeline systems’ principal sources of liquidity are cash generated from operating activities, bank credit facilities and equity contributions from their partners. Our pipeline systems fund operating expenses, debt service and cash distributions to partners primarily with operating cash flow. Great Lakes also funds its debt repayments with cash calls to its partners.

Capital expenditures are funded by a variety of sources, including cash generated from operating activities, borrowings under bank credit facilities, issuance of senior unsecured notes or equity contributions from our pipeline systems’ partners. The ability of our pipeline systems to access the debt capital markets under reasonable terms depends on their financial position and general market conditions.

We believe that our pipeline systems’ ability to obtain financing at reasonable rates, together with their history of consistent cash flow from operating activities, provide a solid foundation to meet their future liquidity and capital resource requirements. The Partnership’s pipeline systems monitor the creditworthiness of their customers and have credit provisions included in their tariffs that allow them to request credit support as circumstances dictate.

Summary of Great Lakes’ Contractual Obligations

The following table summarizes Great Lakes’ debt outstanding as at March 31, 2011:

(unaudited)	Payments Due by Period
(millions of dollars)	Total		Less than 1 year		Long-term Portion

8.74% series Senior Notes due 2011		10.0		10.0		-
6.73% series Senior Notes due 2012 to 2018		63.0		9.0		54.0
9.09% series Senior Notes due 2012 to 2021		100.0		-		100.0
6.95% series Senior Notes due 2019 to 2028		110.0		-		110.0
8.08% series Senior Notes due 2021 to 2030		100.0		-		100.0
		383.0		19.0		364.0

Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restrictive covenants in the Senior Note Agreements, approximately $206.0 million of Great Lakes’ partners’ capital was restricted as to distributions as at March 31, 2011 (December 31, 2010 – $211.0 million). Current maturities will be funded through cash calls to its partners. As at March 31, 2011, Great Lakes was in compliance with all of its financial covenants.

Summary of Northern Border’s Contractual Obligations

The following table summarizes Northern Border’s debt outstanding as at March 31, 2011:

(unaudited)	Payments Due by Period
(millions of dollars)	Total		Less than 1 year		Long-term Portion

$250 million Credit Agreement due 2012		191.0		-		191.0
6.24% Senior Notes due 2016		100.0		-		100.0
7.50% Senior Notes due 2021		250.0		-		250.0
		541.0		-		541.0

As at March 31, 2011, Northern Border had outstanding borrowings of $191.0 million under its $250.0 million revolving credit agreement and was in compliance with the covenants of the agreement. The weighted average interest rate related to the borrowings on the credit agreement was 0.56 percent at March 31, 2011 (2010 – 0.50 percent).

CONTINGENCIES

Legal

Various legal actions or governmental proceedings that have arisen in the ordinary course of business are pending. Our pipeline systems believe that the resolution of these issues will not have a material adverse impact on their results of operations or financial position. Please read Part II, Item 1. ‘‘Legal Proceedings’’ for additional information.

Environmental

We believe that our pipeline systems are in substantial compliance with applicable environmental laws and regulations.

RELATED PARTY TRANSACTIONS

Please read Note 9 within Item 1. “Financial Statements” for information regarding related party transactions.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

OVERVIEW

Market risk is the risk of loss arising from adverse changes in market rates. Our primary risk management objective is to protect earnings and cash flow and, ultimately, unitholder value. We do not use financial instruments for trading purposes.

We are exposed to market risk primarily from interest rate fluctuations. The Partnership and our pipeline systems are also exposed to other risks such as credit risk, liquidity risk and foreign exchange fluctuations. Our exposure to market risk discussed below includes forward-looking statements and is not necessarily indicative of actual results, which may not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated, based on actual market conditions.

We record derivative financial instruments on the balance sheet as assets and liabilities at fair value. We estimate the fair value of derivative financial instruments using available market information and appropriate valuation techniques. Changes in the fair value of derivative financial instruments are recognized in earnings unless the instrument qualifies as a hedge and meets specific hedge accounting criteria. Qualifying derivative financial instruments’ gains and losses may offset the hedged items’ related results in earnings for a fair value hedge or be deferred in accumulated other comprehensive income for a cash flow hedge.

MARKET RISK AND INTEREST RATE RISK

From time to time, and in order to finance our business and that of our pipeline systems, the Partnership and our pipeline systems issue debt to invest in growth opportunities and provide for ongoing operations. The issuance of debt exposes the Partnership and our pipeline systems to market risk from changes in interest rates that affect earnings and the value of the financial instruments we hold.

The Partnership and our pipeline systems use derivatives as part of our overall risk management policy to manage exposures to market risk resulting from these activities within established policies and procedures. Derivative contracts used to manage market risk generally consist of the following:

·	Swaps – contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Partnership and our pipeline systems enter into interest rate swaps to mitigate the impact of changes in interest rates.

Options – contractual agreements to convey the right, but not the obligation, for the purchaser to buy or sell a specific amount of a financial instrument at a fixed price, either at a fixed date or at any time within a specified period. The Partnership and our pipeline systems enter into option agreements to mitigate the impact of changes in interest rates.

Interest rate risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in the market interest rates. Our interest rate exposure results from our Senior Credit Facility, which is subject to variability in London Interbank Offered Rate (LIBOR) interest rates. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.

Our interest rate swaps and options are structured such that the cash flows match those of the Senior Credit Facility. The notional amount hedged was $300.0 million at March 31, 2011 (December 31, 2010 – $375.0 million). $300.0 million of variable-rate debt is hedged by an interest rate swap through December 12, 2011, where the weighted average fixed interest rate paid is 4.89 percent. $75.0 million of variable-rate debt was hedged by an interest rate swap through February 28, 2011, where the fixed interest rate paid was 3.86 percent. In addition to these fixed rates, the Partnership pays an applicable margin in accordance with the Senior Credit Facility agreement.

At March 31, 2011, the fair value of the interest rate swaps accounted for as hedges was classified as a current liability and was negative $9.9 million (December 31, 2010 – negative $13.8 million). The fair value of the interest rate swaps was calculated using the period-end interest rate; therefore, it is expected that this fair value will fluctuate over the year as interest rates change.

At March 31, 2011, we had $475.0 million (December 31, 2010 – $483.0 million) outstanding on our Senior Credit Facility. Utilizing the conditions of the interest rate swaps, if LIBOR interest rates hypothetically increased by one percent (100 basis points) compared to the rates in effect at March 31, 2011, our annual interest expense would have increased and our net income would have decreased by $1.8 million; and if LIBOR interest rates hypothetically decreased to zero percent compared to the rates in effect at March 31, 2011, our annual interest expense would have decreased and our net income would have increased by $0.6 million. These amounts have been determined by considering the impact of the hypothetical interest rates on unhedged debt outstanding as at March 31, 2011.

Northern Border utilizes both fixed-rate and variable-rate debt and is exposed to market risk due to the floating interest rates on its revolving credit facility. Northern Border regularly assesses the impact of interest rate fluctuations on future cash flows and evaluates hedging opportunities to mitigate its interest rate risk. As at March 31, 2011, 65 percent of Northern Border’s outstanding debt was at fixed rates (December 31, 2010 – 65 percent).

If interest rates hypothetically increased by one percent (100 basis points) compared with rates in effect at March 31, 2011, Northern Border’s annual interest expense would increase and its net income would decrease by approximately $1.9 million; and if interest rates hypothetically decreased to zero percent compared with rates in effect at March 31, 2011, Northern Border’s annual interest expense would decrease and its net income would increase by approximately $0.6 million.

Great Lakes and Tuscarora utilize fixed-rate debt; therefore, they are not exposed to market risk due to floating interest rates. Interest rate risk does not apply to North Baja, as it currently does not have any debt.

OTHER RISKS

The Partnership is influenced by the same factors that influence our pipeline systems. None of our pipeline systems own any of the natural gas they transport; therefore, they do not assume any of the related natural gas commodity price risk with respect to transported natural gas volumes.

Counterparty credit risk represents the financial loss that the Partnership and our pipeline systems would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of its contracts with the Partnership or its pipeline systems. Our maximum counterparty credit exposure with respect to financial instruments at the balance sheet date consists primarily of the carrying amount, which approximates fair value, of non-derivative financial assets, such as accounts receivable, as well as the fair value of derivative financial assets. At March 31, 2011, the Partnership’s maximum counterparty credit exposure consisted of accounts receivable of $7.6 million (December 31, 2010 – $7.6 million) and there were no significant amounts past due or impaired.

The Partnership and our pipeline systems have significant credit exposure to financial institutions as they provide committed credit lines and critical liquidity in the interest rate derivative market, as well as letters of credit to mitigate exposures to non-creditworthy parties. Due to the deterioration of global financial markets in 2008 and 2009, we continue to closely monitor the creditworthiness of our counterparties, including financial institutions. Overall, we do not believe the Partnership has any significant concentrations of counterparty credit risk.

Liquidity risk is the risk that the Partnership and our pipeline systems will not be able to meet their financial obligations as they become due. Our approach to managing liquidity risk is to ensure that we always have sufficient cash and credit facilities to meet our obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damage to our reputation. The Partnership has a committed revolving bank line of $250.0 million maturing in December 2011 and as at March 31, 2011, the Partnership had no drawings on this facility, leaving the full $250.0 million available. The Partnership expects to renew its Senior Credit Facility prior to its maturity date of December 12, 2011. In addition, Northern Border has a committed revolving bank line of $250.0 million maturing in April 2012 and as at March 31, 2011, $191.0 million was drawn on this facility.

The Partnership does not have any material foreign exchange risks.

Item 4. Controls and Procedures

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

As required by Rule 13a-15(e) under the Exchange Act, the management of our General Partner, including the principal executive officer and principal financial officer, evaluated as of the end of the period covered by this report the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. The Partnership’s disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives. Based upon and as of the date of the evaluation, the management of our General Partner, including the principal executive officer and principal financial officer, concluded that our disclosure controls and procedures, as of the end of the period covered by this report, were effective to provide reasonable assurance that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is (a) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (b) accumulated and communicated to the management of our General Partner, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended March 31, 2011, there was no change in the Partnership’s internal control over financial reporting that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.

PART II

Item 1. Legal Proceedings

Tuscarora operates pursuant to maximum transportation rates approved by the FERC in a July 2006 rate case settlement. A moratorium on the filing of future rate cases under NGA Sections 4 or 5 expired on May 31, 2010. On February 28, 2011, the PUCN and NV Energy filed a complaint with the FERC, pursuant to Section 5 of the NGA, alleging that Tuscarora's rates for jurisdictional services may be unjust and unreasonable and asking the FERC to investigate Tuscarora’s rates and to establish an interim rate reduction. Tuscarora filed its Answer to the complaint on March 18, 2011. The Complainants filed a Motion for Leave to Answer and Answer on March 30, 2011. We are currently awaiting the FERC’s action on the Complaint and Answers, which is not subject to any deadline.

On July 27, 2009, North Baja and GTN filed arbitration with American Arbitration Association in Portland, Oregon for approximately $26 million in damages related to performance, integrity and reliability issues associated with certain equipment purchased from Rolls Royce Energy Systems, Inc. (RREI). GTN and North Baja allege that equipment purchased from RREI in 2001 is defective and that RREI breached its contract and warranties. The arbitration is in the discovery phase.

In addition to the above written matters, we and our pipeline systems are named defendants in lawsuits and governmental proceedings that arise in the ordinary course of our business.

Item 1A. Risk Factors

The following updated risk factors should be read in conjunction with the risk factors disclosed in Part I, Item 1A. “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2010.

Risks Inherent in Our Business

If the tariff rates of our pipeline systems were successfully challenged, our pipeline systems’ could be required to reduce their tariff rates, which would reduce our revenues and cash available for distributions.

If a customer of one of our pipeline systems were to file a complaint against our pipeline systems’ existing tariff rates, or the FERC were to initiate an investigation of our pipeline systems’ existing rates, then our pipeline systems’ rates could be subject to detailed review. If our pipeline systems’ existing rates were found to be unjust and unreasonable, they could be ordered to reduce their rates prospectively. Any such reductions may result in lower revenues and cash flows, which could impact our ability to make distributions.

Please see Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations − Regulatory Environment − FERC Rate Proceedings − Tuscarora Complaint” for additional information.

Risks Related to the Acquisition

The Acquisition is subject to certain closing conditions.

On April 26, 2011, we entered into definitive agreements to acquire 25 percent of the equity interest in each of Bison and GTN. The Acquisition is expected to close in May 2011, however, the completion of the Acquisition is subject to certain closing conditions, including the ability of the seller to make certain representations and warranties and the absence of a material adverse effect at closing. We cannot assure you that these conditions will be met and as a result there can be no assurance that the Acquisition will be completed.

Following the Acquisition, if completed, we will not own a controlling interest in GTN or Bison, and we will be unable to cause certain actions to take place without the agreement of other members. As a result, we will be unable to control the amount of cash we will receive from those operations and we could be required to contribute significant cash to fund our share of their operations. If we fail to make these contributions our ownership interest would be diluted.

The major policies of GTN and Bison will be established by their respective management committees, each of which will consist of three individuals who are designated by TransCanada and one individual who is designated by us consistent with the relative ownership interest percentages. The management committees require the affirmative vote of a majority of the members’ ownership interests to take any action. Because of these provisions, without the concurrence of TransCanada, we will be unable to cause GTN or Bison to take or not to take certain actions, even though those actions may be in the best interests of the Partnership, GTN or Bison. Conversely, because TransCanada will hold a majority interest in GTN and Bison, it will have the authority to make most decisions and take most actions without our approval, subject to limited approval rights that we have.

Following the Acquisition, GTN and Bison may seek additional capital contributions. Our funding of these capital contributions would reduce the amount of cash otherwise available for distribution to our unitholders. Additionally, in the event we elect not to, or are unable to, make a capital contribution to GTN or Bison, our ownership interest would be diluted.

GTN may not be able to maintain existing customers or acquire new customers when its current shipper contracts expire or customers may recontract for shorter periods or at less than maximum rates.

The GTN Pipeline competes for WCSB gas supplies seeking downstream markets. Once Ruby pipeline is in service, which is expected in mid-2011, GTN will also compete with Ruby pipeline, which will deliver Rocky Mountain basin gas supplies into the California market. Such competition has and may adversely affect GTN’s ability to extend and replace contracts on terms comparable to prior contracts, if at all. For example, Pacific Gas and Electric has notified GTN that it would not renew its current contract for 250 MDth/d that expires in October 2011. If GTN is not able to maintain existing customers or contract with new customers when current shipper contracts expire, its revenue and ability to make distributions may be adversely affected.

If the Acquisition is not accretive our future growth may be limited.

There can be no assurance that the Acquisition, if completed, will result in an increase in cash per common unit generated from operations.

Item 5. Other Information

Refer to Part I, Item 2. ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Developments – Partnership − GTN and Bison Acquisition” for additional information.

Item 6. Exhibits

No.	Description
10.1	Fifth Amendment to Operating Agreement by and between Tuscarora Gas Transmission Company and TransCanada Northern Border Inc. dated December 31, 2010.
31.1	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 27th day of April 2011.

TC PIPELINES, LP

(A Delaware Limited Partnership)

By its General Partner, TC PipeLines, GP, Inc.

By: /s/ Steven D. Becker

Steven D. Becker

President

TC PipeLines GP, Inc. (Principal Executive Officer)

By: /s/ Robert C. Jacobucci

Robert C. Jacobucci

Controller

TC PipeLines GP, Inc. (Principal Financial Officer)

EXHIBIT INDEX

No.	Description
10.1	Fifth Amendment to Operating Agreement by and between Tuscarora Gas Transmission Company and TransCanada Northern Border Inc. dated December 31, 2010.
31.1	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.